Fracturing of various subterranean formations with water, carbon dioxide, and other carrier fluids has been practiced for some time. It will be understood by those skilled in the art that fracturing fluid, carrier gas or simply gas, as utilized herein, refers to liquid phase, gas phase, supercritical fluid, or combination thereof. Typically, wells stimulated with a CO2 based fracturing fluid (which may include water or some other fluid), after separation of any solids, liquids and/or oil, emit an initial raw fluid, often referred to as flow back fluid, that is a mixture of fracturing fluid CO2 and reservoir fluid. Thus, flow back fluid can contain natural gas, other hydrocarbons and contaminates, such as hydrogen sulfide (H2S), water (H2O) and CO2.
The initial gas flow from the well stimulated with a CO2 based fracturing fluid contains high CO2 concentrations (80-100%), with the balance of the gas formed by methane, other light hydrocarbons, water, and minor components. If no treatment of the gas is performed during this period, the entire gas flow would need to be flared as the CO2 content is too high to proceed into the gas gathering pipelines. The flow back CO2 concentration declines over time as the gas continues to flow, so that after approximately 10-30 days the CO2 concentration falls to a level of 5-10% CO2 or lower.
The fluid from the well cannot be sent to a downstream processing facility or pipeline as product until is below the maximum specified CO2 concentration. The requirement for CO2 concentration for downstream processing facility or pipeline gas is typically in the range of 2-10 mol %. In many cases, the fluid/gas is vented or flared until it meets the CO2 concentration specification, at which point it can be used as a product. When flow back fluid contains >70% CO2, flaring operation requires addition of natural gas to maintain or otherwise render the flaring operation self-sustainable. Thus, the valuable hydrocarbons contained in the fluid exiting the well are initially wasted and additional natural gas is utilized.
One object of this invention is to provide a method and system for treating flow back gas utilizing a two-stage membrane process during the period that the gas contains high concentrations of CO2 by volume, separating the CO2 from the natural gas components, and providing pipeline-quality natural gas (approximately 5% CO2 by volume) to the gas collection system. A secondary object is to recover condensable hydrocarbons and provide those liquids to the onsite storage system. The liquids which condense from the flowback gas are described herein as natural gas liquids, or NGL. A further object is to recover CO2 from flow back fluid of a newly fractured well, which can be liquefied and reused to fracture a nearby well and reduce the logistical issues of providing large amounts of liquid CO2 to often remotely-located wells. Additional equipment would be required to allow for the recovery of CO2 in combination with the system described herein, as taught in U.S. patent application Ser. No. 14/166,304 filed Jan. 28, 2014, which is incorporated herein by reference.
Use of the method and system of the invention allows recovery of valuable natural gas and natural gas liquids at an earlier point in the production of the well, and avoids flaring of the entire well output during the initial 30 days or so of initial gas flow. Furthermore, the method and system of the invention allows one to (a) reduce the cost of providing CO2 for well fracturing, (b) reduce the natural gas consumption necessary for flaring operations and (c) recover gaseous and liquid hydrocarbons separately.
Other objects and aspects of the present invention will become apparent to one of ordinary skill in the art upon review of the specification, drawings and claims appended hereto.